Method for terminating or reducing water flow in a subterranean formation

ABSTRACT

This invention relates to a method of reducing the deleterious effects of water production in a subterranean formation by placing an aqueous phase polymer and/or resin, which at a designated set up time, solidifies and blocks water conduits. This invention pertains specifically to a method of placing the polymer and displacing the polymer and/or resin to establish post treatment gas and oil permeability. Novel polymers and/or resins for use as a water barrier are disclosed

BACKGROUND OF THE INVENTION

(i) Field of The Invention

This invention pertains to a method for shutting off or reducing theunwanted production of water from wells in a gas and oil-bearingformation due to flow through paths of least resistance.

(ii) Description of the Related Art

In the operation of wells used in the recovery of gases and associatedliquids from subterranean formations unwanted passage of water canseverely disrupt or in fact terminate the desired operation of a well.Frequently, a hydrocarbon reservoir contains water, either due toindigenous water or injected water. Water bypassing is often observedsince the mobility of the water is usually high and therefore, when apressure gradient is imposed, water tends to flow more readily than thehydrocarbon phases. The effects of water production are deleterious, asthe water must be separated from saleable hydrocarbon products anddisposed of in an environmentally safe manner. This can result in thewell being shut in because of the adverse economics of increasedseparation and disposal costs of water compared to the declininghydrocarbons as water flow increases. In addition, the produced watercan kill the gas flow in the well when the hydrostatic pressure of thewater column is greater than the reservoir pressure (which prevents gasor oil flow). Artificial lifting costs to handle the water can addsubstantially to the cost of production.

These problems are not unique and the solutions have traditionallyinvolved apparatus, methods, and compositions adapted to cover, seal orotherwise plug the openings thereby shutting off or reducing the passageof water. A barrier often is considered for unwanted liquid and gasproduction mitigation. There are a number of articles and patentsdescribing various techniques which have been used to reduce waterproduction due to coning or bottom water flow. Examples of these areKarp. Et al., Horizontal Barrier for Controlling Water Coning, Journalof Petroleum Technology, Vol. XX, pp. 783-790, 1962, Canadian Patent No.1,277,936 to Costerton et al. and U.S. Pat. No. 5,062,483 issued toKisman and Russell. These patents and the article discuss specificmethods for isolation of bottom water flow. Polymers, such aspolyacrylamide and polyphenolic resins, have been used in the past toenter the water conduits in the reservoir, and at a predefined time,setup or solidify to block or substantially impede water flow in theconduits. Since these solutions are aqueous they have a preference forthe water conduits because of the low interfacial tension between twoaqueous fluids. This can result in the aqueous solutions mixing with thelarge volumes of water and becoming unduly diluted.

These treatments have been successfully used for plugging high waterflow regions but, due to their density, many times these treatments aregravimetrically unstable and are therefore less effective for bottomwater control. Some of these previous applications are described in U.S.Pat. No. 4,683,949; U.S. Pat. No. 5,358,043; U.S. Pat. No. 5,418,217;U.S. Pat. No. 4,744,418; U.S. Pat. No. 5,338,465; U.S. Pat. No.4,844,168 and U.S. Pat. No. 3,884,861.

Another technique disclosed in U.K. Patent GB 2,062,070A proposed aviscosified polymer which would be emulsified in oil and injected into agas-producing formation to control bottom water production. This,however, was not successful due to the fact that the inherently highviscosity precluded the polymer from entering into many of the zones inwhich the water was flowing. Also, polymer gel emulsified in oil andstabilized with surfactants often suffer from phase separation in porousmedia.

SUMMARY OF THE INVENTION

It is a principal object of the present invention to provide a meanswhereby a water-blocking agent can be placed on top of or near the topof the oil-water or gas-water contact in a reservoir where thehydrocarbon phase (oil and/or gas) is underlain by a bottom water zone.

It is another object of the invention to provide a means whereby awater-blocking agent can be placed in the conduits (fractures,wormholes, high permeability streaks, near well-bore deficiencies, etc.)to prevent water to migrate to the well-bore from aquifers above, belowand from the edge of the production zone.

It is a further object of this invention to provide ease of injectioninto production or injection wells and therefore must be as a liquidphase. A further object of the invention is the provision of chemicalsfor low viscosity of the chemical during placement and, upon appropriateplacement and setup time, high viscosity to reduce water flow,particularly to block water flow vertically or through thief zones.

The invention has advantages whereby, in using available water and crudeoil or any designated liquid hydrocarbon phase of a specific density,the overall density of the chemical treatment can be adjusted so thatthe treatment floats on water and has a modified or unmodified viscosityas well. Another advantage of the invention is that by increasing thedelta pressure to inject the polymer, capillary forces in both the oil-and water-bearing portions of the rock are overcome so that the blockcan be total. More particularly, this invention relates to a method ofplacing aqueous polymers and/or resins into the water conduits of thehydrocarbon reservoir. When these set up or solidify, the unwanted waterproduction is shut off or reduced.

The challenge is to place these treatments without adversely effectingthe relative permeability of the reservoir for gas or oil production andwithout invading the hydrocarbon zones. This can be accomplished in oneembodiment of the invention for gas wells with or without oil by theutilization of water and a gas such as nitrogen gas injected before thepolymer is injected downhole and a liquid solvent such as methanoland/or water and a gas such as nitrogen gas after the polymer isinjected downhole. By following the protocol as will be described, notonly is water production reduced or shut off but also any riskassociated with blocking off or restricting the flow of gas or oil isminimized. This can be accomplished in another embodiment of theinvention by placing an emulsion (with a density intermediate the oilphase and water phase so it floats) between the oil production zone andthe underlying aquifer. This will stop or reduce the water from coningup from below. These embodiments will optimize the post treatmentproduction by ensuring the gas and oil permeability is maintained andpotentially improved.

An effective aqueous solution of a polymer such as phenolformaldehydesold under the trade-mark DIREIT™ having low initial viscosity withgelation over a predetermined time interval can be injected into theformation as an aqueous polymer gel or as a polymer gel-in-oil emulsionwhich is lighter than water.

Another polymer gel having a relatively low initial viscosity withgelation over a predetermined period of time is polyacrylamide soldunder the trade-mark ALOFLOOD 2545®, which can be injected into theformation as an aqueous polymer gel or as a polymer gel-in-oil emulsionlighter than water.

A preferred polymer gel-in-oil emulsion comprises a polymer formed froma 1,2-substituted ethene compound such as a substituted styrlpyridiniumcompound sold under the trade-mark HYDRAGEL™ and described in publishedU.K. Patent Application Serial No. 96 194 19.6, preferably injected intothe formation as an aqueous oil-in-gel emulsion.

In its broad aspect, the method of the invention for placing an aqueouspolymer in the water conduits of the production zone of a gas or oilreservoir to form a barrier to shut off or reduce unwanted production ofwater, through a well-bore tubing in communication with the productionzone of the gas or oil reservoir, comprises injecting water into theproduction zone to establish an injection rate into the production zone,and injecting the aqueous polymer into the production zone at saidinjection rate, said aqueous polymer selected from the group consistingof phenolformaldehyde, polyacrylamide and 1,2-substituted ethane. Theaqueous polymer can also be injected as an aqueous oil-in-polymeremulsion. The aqueous polymer can be a substituted styrolpyridinumcompound in a concentration of at least about 0.5 wt % in an aqueoussolvent and may be emulsified with up to 50 wt % oil.

In accordance with another aspect of the invention, the method forplacing an aqueous polymer gel in the water conduits of the productionzone of a gas or oil reservoir to form a barrier to shut off or reduceunwanted production of water, through a well-bore tubing incommunication with the production zone of the gas or oil reservoir,comprises injecting water into the production zone to establish aninjection rate into the production zone, injecting N₂ or CO₂ gas intothe formation in a first gas injection in an amount sufficient todisplace the water or flushing the water to surface with N₂ or CO₂ in anamount sufficient to displace the water, injecting the aqueous polymergel into the production zone at said injection rate, injecting a solventselected from methanol, water or methanol and water, for reducinginterfacial tension, and flushing the solvent from the well-bore tubingand communicating the well-bore with the production zone with N₂ or CO₂gas in a second gas injection to optimize gas permeability in theproduction zone. The method preferably comprises ascertaining the N₂ orCO₂ first gas injection rate while injecting gas into the formation todisplace the water, monitoring the N₂ or CO₂ second gas injection rate,comparing the N₂ or CO₂ gas first injection rate with the N₂ or CO₂second injection rate, and increasing the N₂ or CO₂ gas second injectionrate to match the N₂ or CO₂ first injection rate to re-establish andoptimize the gas permeability in the production zone.

The aqueous polymer gel preferabl is at least one of phenolformaldehyde,polyacrylamide or a 1,2-substituted ethane, more preferably asubstituted styrolpyridinum compound. The aqueous polymer gel can beemulsified with up to 50 wt % oil and stabilized with a surfactant.

In accordance with another embodiment, by incorporating at least atwo-stage sequential treatment, larger conduits of water flow may beblocked upon injection of a fist horizontal stage whereas a second stagewill serve to impede undesirable fluid flow (water or gas) from thesecondary flow conduits. Moreover the second stage of the treatment hasa lower vertical limit provided by a generally horizontal barrier downthrough which the second stage will not pass. This would have specificapplication to treatments where the second stage has a specific gravityhigher than 1.0 but this layered approach would also be very effectivefor systems where the second or subsequent stages are less or more densethan water.

The invention describes a composition of the emulsion which isgravimetrically stable with respect to the oil-water or gas-watercontact and will form a first stage of a water impermeable solid or gelphase, preferably followed by a second stage which will be largelyindependent of specific gravity considerations and which will complementthe first stage. By designing the viscosity and density of thetreatment, vertical flow of undesirable phases can be reduced and flowfrom thief zones can also be targeted.

BRIEF DESCRIPTION OF THE DRAWINGS

The method of the invention will be described with reference to theaccompanying drawing, in which:

FIG. 1 is a graph illustrating relative permeability to liquidsaturation in a gas-bearing reservoir;

FIG. 2 is a schematic illustration of a well bore in which thepolyphenolic resin is displaced by N₂;

FIG. 3 is a schematic illustration of a well bore in which thepolyphenolic resin is displaced by methanol;

FIG. 4 is a graph, of Case 1, showing daily gas and water productionafter application of the method of the invention; and

FIG. 5 is a graph, of Case 2, showing daily water, gas, and condensateproduction after application of the method of the invention.

DESCRIPTION OF THE PREFERRED EMBODIMENT

The requirement of this present invention, pertaining to shutting off orreducing water production where water is coning up to the productionperforations, through partially consolidated or unconsolidated sands isthat the density of the emulsion phase must be greater than that of thehydrocarbon, i.e. oil or liquified gas, and less than that of theformation water. By injecting this intermediate-density emulsion phaseinto the reservoir, it will necessarily settle due to gravity to thepoint where it sits on top of the water. By appropriate design of theproperties of the emulsion (density and viscosity) the treatment canalso be specifically placed in high permeability layers or zones. Oncein place, the setup time mechanism must be such that it gels or becomesa solid phase and thereby offers significant resistance to unwanted gasor water (or any other undesirable phase) production in the region ofthe near well-bore or where the coning response exists. The emulsionphase must have the properties that it has adequate setup time, adequaterigidity to withstand differential pressure and the viscosity is suchthat it will flow easily into various types of rock. The treatment ispossible to be placed both from the current production perforations aswell as perforations which may be newly created.

The aqueous component of the invention would include a polymer which hasbeen designed at a specific concentration for setup time which isconsistent with the physical situation. The composition of the aqueouspolymer phase of the emulsion can be those of a polyacrylamide andcross-linking nature such as disclosed in U.S. Pat. No. 4,693,949, No.5,358,043 or No. 5,418,217 and the compositions of the phenolformaldehyde as exemplified in the U.S. Pat. No. 3,884,861 and U.S. Pat.No. 4,091,868 or Canadian Patent No. 1,187,404. The oil component can bea refined oil including diesel, mineral oil, benzene, kerosene or thelike. Crude oils can also be used but preferably refined oil productswith lower densities should be used from a density perspective. A smallamount of surfactant usually is required to stabilize emulsions.

There are many challenges to overcome in properly placing an aqueoussolution in a reservoir to shut off or reduce water migration to theproduction perforations in a producing well, such as a producing gaswell with or without oil production. Before proceeding with anapplication of the aqueous solution, an injection rate for reservoircompatible water should be established to ascertain whether the polymeror resin could be safely injected into the subterranean formation underpressure and time limitations. The well may have to be stimulated inorder to increase the injection rate. The problem with this injectiontest is that the water saturation in the near well bore region canincrease and, as a consequence, reduce the relative permeability of gas.As a result the gas flow is reduced, or in fact, shut off. FIG. 1illustrates how the increase in water saturation effects the relativepermeability of gas. To overcome this problem, gas (N₂ or CO₂) should beinjected into formation, after the injection test with water iscomplete, to displace the water and to re-establish the gas saturationand the conduits to the gas zone.

Another possible problem is that the water used in the injection testcan charge up the reservoir, i.e. fill the large voids so more pressureis required to inject the subsequent polymer and/or resin into thereservoir. The increase in pressure can force the polymer into the gaszone if the increase in differential pressure (AP) overcomes thecapillary pressure keeping the aqueous solution out of the gas zone. Toovercome this problem, the water used for the injection test can beflushed to surface using gas (N₂ or CO₂). The gas is injected down thetubing and the water is flushed back through the annulus, or vice-versa.If a permanent packer to isolate the tubing from the casing is in place,coil tubing will be required to perform this task. If coil tubing is notan option, after the feed rate with water is performed the water in thewell bore should be displaced into formation with gas and theapplication with the polymer delayed for 24 hours to allow the pressurein the reservoir to reach equilibrium. Once the water is displaced, afeed rate for gas should then be established.

A gas such as nitrogen gas (N₂), carbon dioxide (CO₂), and the likegases is then injected. The volume of gas, e.g. N₂, will be calculatedto flush all the fluids out of the tubing and/or annulus and toestablish gas saturation in the near well bore matrix. With the gassaturation assured, the subsequent aqueous treatment will then benefitfrom capillary pressure selectivity in addition to permeabilitycontrasts to drive the aqueous phase treatment into the region where thewater is flowing. Once the treatment is injected, a solvent such asmethanol is injected and then a gas such as N₂ injected. The liquidsolvent will reduce interfacial tension (Wr) for the subsequent gasinflow to the well-bore and will permit less draw down pressure beingrequired for the subsequent production of gas. The solvent will helpensure that the aqueous solution is cleared from the perforations. Ifthe aqueous solution is displaced with only a gas, then once the tubingand/or annulus volume have been displaced, the gas may only invade thegas zone through the very top of the perforations. This would occurbecause there is no capillary pressure between two gases and gases arevery compressible. (refer: FIG. 2) This would result in the lowerperforations being blocked off. Because methanol is a less compressiblefluid than a gas such as N₂, it will continue to displace the aqueoussolution to enable the perforations to be cleared. (refer: FIG. 3). Thegas such as N₂ will ensure gas permeability is maintained to optimizepost treatment gas production.

A description of exemplary field tests of embodiments of the method ofthe invention are as follows.

Step by Step Field Test Summary for Shutting Off or Reducing Water in aGas Well with or Without Oil

1. Connect the aqueous polymer mixing and pumping unit along with thegas (e.g. N₂ or CO₂) pumping unit to well head.

2. Ascertain the injection rate (m³/minute) for an aqueous polymersolution such as phenolformaldehyde by first injecting reservoircompatible water into the formation to ensure there is adequate time(including a margin of safety) to inject the designed volume of polymerbefore it sets up. The reservoir may need to be stimulated to achievethe fluid injection rate.

3. The water used in the injection test in Step 2 can be flushed back tosurface or forced into the reservoir using gas (e.g. N₂ or CO₂).

4. Ascertain the injection rate (m³/minute) of gas (e.g. N₂ or CO₂) atStandard Temperature and Pressure (S.T.P.) to ensure all liquids arecleared from well-bore and to establish gas conduits into the reservoirformation. This rate can be compared to the injection rate of the gasafter the polymer has been displaced to help determine if gaspermeability has been reduced.

5. Mix the programmed volume and concentration of aqueous polymer.

6. Follow the gas from Step 4 with the programmed volume of water(optional) to ensure the aqueous polymer does not plug off the gaspermeability. In many cases the injection pressure increases when theaqueous fluid first enters the formation and this can force the liquidinto the gas zone until the conduits to the aquifer are established. Itis much preferred this liquid is water rather than the polymer whichonce set will reduced the post treatment permeability to gas.

7. Follow the water (optional) with injection of the mixed aqueouspolyer solution, ensuring that the rates are as low as possible and arestill able to safely place/displace solution into the formation beforeit sets. (Ensure surface pumping pressure added to the hydrostaticpressure does not exceed the fracture pressure of the reservoir).

8. Follow the aqueous polymer (optional) with the programmed volume ofsolution such as methanol and/or water to ensure the perforations areclear of the displaced aqueous polymer to access the hydrocarbon zone ofthe reservoir.

9. Follow Step 8, with the programmed volume of gas to not only ensurethe aqueous polymer is displaced from the well-bore but also conformcommunication is established to the gas zone. (This can be monitored bysurface pressure since the downhole pressure and temperature are known).This gas can be continuously injected until the polymer has set toensure gas permeability is maintained.

10. If the initial post treatment injection rate for gas has beenreduced significantly by comparison with the rate achieved in Step 4,the injection rate of the gas (e.g. N₂ or CO₂) can be increased to helpre-establish the gas permeability and/or an acid treatment can beperformed in the hydrocarbon zone.

11. Shut in the well for 12 hours or until it can be assured that theaqueous polymer is set

Step by Step Field Test Summary for Shutting Off or Reducing WaterConing in an Oil Well

1(a) If displacing the polymer through existing perforations, set apacker (retainer) above the production perforations and ascertain aninjection rate (m³/minute) with water through these perforations intothe formation to ensure there is adequate time (including a margin ofsafety) to inject the designed volume of polymer before it sets up. Thereservoir may need to be stimulated to achieve the desired rate.

1(b) If displacing the polymer at, or just above the oil water contact,then perforate this interval; set a packer (retainer) above theseperforations and ascertain the injection rate (m³/minute) with reservoircompatible water through these perforations into the formation to ensurethere is adequate time (including a margin of safety) to inject thedesigned volume of polymer before it sets up. The reservoir may need tobe stimulated to achieve the desired rate. If the well has beencompleted and there are perforations above the packer (retainer) in theoil production zone then trickle oil into these production perforationsthrough the annulus to ensure the fluids injected through the bottomperforations do not migrate upwardly above the water/oil interface.

2. Connect the aqueous polymer mixing and pumping unit along with theoil pumping unit if require (Step 1(b) above) to the well head.

3. Mix the programmed volume and concentration of an aqueous polymer ofthe invention.

4. Place the polymer to the bottom of the tubing, 1(a) activate theretainer and shut in the annulus, then displace the aqueous polymer intothe reservoir formation, ensuring the surface pressure added to thehydrostatic pressure of the column of fluids does not exceed thereservoir rock fracture pressure. Under displace the polymer, deactivatethe retainer and backwash the under displaced polymer to surface. 1(b)fill the well with crude oil, then place the polymer to the bottom ofthe well-bore tubing, activate the packer (retainer) and displace theaqueous polymer into the formation while keeping positive pressure onthe annulus so as to trickle oil through the production perforations.Under displace the aqueous polymer, deactivate the retainer and backwashthe aqueous polymer to surface.

5. Shut in the well for along enough period to ensure the polymer hasset (usually 12 hours).

The method of the invention will now be described with reference to thefollowing non-limitative examples, in which the aqueous polymer isphenolformaldehyde (DIREXIT™). Case 1: Water Shut Off - Gas (FIG. 4)Volume of 9.66 m³ (60.75 bbl) Treatment: Formation Sandstone Type:Work-over Injected 9.66 m³ DIREXIT ™ at 600 1/min at 1000 kPa Report:using N₂ to ensure gas conduits remained open. The purpose of thistreatment was to shut off water coming from the aquifer throughhydraulically induced fractures. Before this treatment, there had beenonly tested production because of the high volumes of water. Result:Before the treatment, the entire life of the well was in suspend modewith initial tests of 530 mscf/day gas and 190 bbl/day water. After thetreatment the well has averaged 460 mscf/day gas and 3 bbl/day water andis an economic success. Case 2: Water Shut Off - Gas (FIG. 5) Volume of12 m³ (75.5 bbl) Treatment: Formation Carbonate Type: Work-over 12 m³was injected at 300 l/min at 2000 kPa. Report: Purpose of treatment wasto stop water flow from bottom water through natural fractures. Result:Results of this treatment are excellent - gas has increased from 1mmscf/day with artificial lift to 1.7 mmscf/day with no artificial lift.After treatment, condensate increased from 1.5 m³/day to 6.5 m³/day.Workover pay-out was 3 weeks.

Although the foregoing description has proceeded with respect to the useof the aqueous polymer DIREXT™, it will be understood that a polymericmaterial may be used comprising a polymeric material which is at leastpartially formed from a 1,2-substituted ethene compound, for example asusbtituted styrylpyridinium compound, as disclosed in aforementionedU.K. Patent Application Serial No. 96 194 19.6 and published CanadianPatent Application Serial No. 2,266,578, the disclosures of both ofwhich are incorporated herein by reference. A first embodiment of afirst polymeric compound comprises a compound of general formula

or a salt thereof where A and B are the same or different and at leastone comprises a polar atom or group and R¹ and R² independently comprisenon-polar atoms or groups, in a solvent of a type in which ethene itselfis generally insoluble and causing the groups C—C in said compound toreact with one another to form a polymeric structure.

Preferably, R¹ and R² are independently selected from a hydrogen atom oran optionally substituted, preferably unsubstituted, alkyl group.Preferably, R¹ and R² represent the same atom or group. Preferably, R¹or R² represent a hydrogen atom.

Preferably, said solvent is a polar solvent Preferably said solvent isan aqueous solvent. More preferably, said solvent consists essentiallyof water.

Preferably, said compound of general formula I is provided in saidsolvent at a concentration at which molecules of said compoundaggregate. Aggregation of said compound of general formula I may beshown or inferred from the results of various analyses as hereinafterdescribed and any one or more of such analyses may be used. Preferably,said compound of general formula I is provided in said solvent at orabove a concentration suggested by relevant vapour pressure measurementsas being a point of aggregation of the compound.

It is believed that said molecules of compound I form aggregates ormicelles in the solvent, with the C—C bonds aligned with one another sothat the molecules effectively align substantially parallel to oneanother.

Preferably, the molecules align with groups A and B adjacent to oneanother.

Said compounds of general formula I may be provided in said aqueoussolvent at a concentration of at least 0.5 wt %, preferably at least 1.0wt % up to 50 wt % and, more preferably, about 1 to 30 wt %.

A second embodiment of a first polymeric compound comprises a compoundof general formula II

wherein A, B, R¹ and R² are as described above and n in an integer.

A first or second embodiment of a first polymeric compound of generalformula I or II in a solvent can be infinitely mixed with a secondpolymeric compound which contains one or more functional groups capableof reacting with said first polymeric compound, preferably in an acidcatalysed reaction. Said reaction is preferably a condensation reaction.Preferably, said second polymeric compound includes a functional groupselected from an alcohol, carboxylic acid, carboxylic acid derivative,for example, an ester, and an amine group. Preferred second polymericcompounds include optionally substituted, preferably unsubstituted,polyvinylalcohol, polyvinylacetate, polyalkylene glycols, for examplepoolypropylene glycol, and collagen (and any component thereof).

The ratio of the wt % of said first polymeric compound to the wt % ofsaid second polymeric compound (or the sum of the wt % of the secondcompound and any further compounds) in the mixture is found to influencesignificantly the properties of the formulation prepared. The ratio ofthe wt % of said first polymeric compound to that of said secondpolymeric compound may be in the range 0.01 to 100, is preferably in therange of 0.05 to 50 and more preferably in the range 0.3 to 20.

A gel particularly suited for use in the method of the present inventioncomprises mixing the resulting mixture from the combination of the firstpolymeric compound and the second polymeric compound with up to 50 wt %of a hydrocarbon such as oil.

In order to create a stable emulsion, a 0.1 to 2 wt % surfactant hasbeen used. Surfactants such as Tiorco VS (brand name) worked well as didmany other kinds of surfactants. In some cases, the surfactant may notbe required for emulsification but may depend on the reactivity of theoil and the water used or even the polymer or resin used in the aqueousphase of the solution. Mixing may be performed in many ways includingsuch methods as blenders, propellers or jet mixers. The concentration ofthe polymer or resin in the aqueous phase can be varied over abroadrange including below 1 wt % up to an excess of 20 or 30 wt % and up to50 wt %.

The present invention provides a number of important advantages. Byusing available water and crude oil or any designated liquid hydrocarbonphase of a specific density, the overall density of the chemicaltreatment can be adjusted so that the polymer solution floats on waterand has a modified or unmodified viscosity. Once set or gelled, waterflow from coning up into the production perforations of the well iseffectively blocked. Also, by increasing the differential pressure toinject the polymer, capillary forces in the oil, gas and water-bearingportions of the rock are overcome so that the block can be total.

It will be understood, of course, that modifications can be made in theembodiment of the invention illustrated and described herein withoutdeparting from the scope and purview of the invention as defined by theappended claims.

1. A method for placing an aqueous polymer in the water conduits of theproduction zone of a gas or oil reservoir to form a barrier to shut offor reduce unwanted production of water, through a well-bore tubing incommunication with the production zone of the gas or oil reservoir,comprising: injecting water into the production zone to establish aninjection rate into the production zone, and injecting the aqueouspolymer into the production zone at said injection rate, said aqueouspolymer selected from the group consisting of phenolformaldehyde,polyacrylamide and 1,2-substituted ethane.
 2. A method as claimed inclaim 1, in which the aqueous polymer is injected as aqueousoil-in-polymer emulsion.
 3. A method as claimed in claim 2, in which theaqueous polymer is a substituted styrolpyridinum compound in aconcentration of at least about 0.5 wt % in an aqueous solvent.
 4. Amethod as claimed in claim 3, in which aqueous polymer is emulsifiedwith up to 50 wt % oil.
 5. A method for placing an aqueous polymer inthe water conduits of the production zone of a gas or oil reservoir toform a barrier to shut off or reduce unwanted production of water,through a well-bore tubing in communication with the production zone ofthe gas or oil reservoir, comprising: injecting water into theproduction zone to establish an injection rate into the production zone,injecting N₂ or CO₂ gas into the formation in a first gas injection inan amount sufficient to displace the water or flushing the water tosurface with N₂ or CO₂ in an amount sufficient to displace the water,injecting the aqueous polymer into the production zone at said injectionrate, injecting a solvent selected from methanol, water or methanol andwater, for reducing interfacial tension, and flushing the solvent fromthe well-bore tubing and communicating the well-bore with the productionzone with N₂ or CO₂ gas in a second gas injection to optimize gaspermeability in the production zone.
 6. A method as claimed in claim 5,additionally ascertaining the N₂ or CO₂ first gas injection rate whileinjecting gas into the formation to displace the water, monitoring theN₂ or CO₂ second gas injection rate, comparing the N₂ or CO₂ gas firstinjection rate with the N₂ or CO₂ second injection rate, and increasingthe N₂ or CO₂ gas second injection rate to match the N₂ or CO₂ firstinjection rate to re-establish and optimize the gas permeability in theproduction zone.
 7. A method as claimed in claim 5, in which saidaqueous polymer is selected from the group consisting ofphenolformaldehyde, polyacrylamide and 1,2-substituted ethane.
 8. Amethod as claimed in claim 7, in which the aqueous polymer is injectedas aqueous oil-in-polymer emulsion.
 9. A method as claimed in claim 7,in which the aqueous polymer is a substituted styrolpyridinum compoundin a concentration of at least about 0.5 wt % in an aqueous solvent. 10.A method as claimed in claim 7, in which the aqueous polymer isemulsified with up to 50 wt % oil.